The present disclosure relates generally to electrical property measurement and, more particularly, to determining the resistivity or conductivity of formation water in subsurface samples.
This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.
Petroleum, or crude oil, is a flammable liquid that includes a mixture of various compounds, such as hydrocarbons and other organic compounds, and occurs naturally in subsurface formations. Natural gas is a flammable gas that may found together with petroleum and other hydrocarbon fuels. Petroleum may have been formed by the exposure of ancient organic material that settled onto lake or sea bottoms to intense heat and/or pressure. Today, wells drilled into subsurface formations associated with these ancient bodies of water may be used to recover the petroleum. The underground pressure found in some formations may be sufficient to force the petroleum to the surface. In other formations, more expensive techniques, referred to as secondary and tertiary methods, may be used to bring the petroleum to the drilled shaft, or wellbore. The recovered petroleum from the wellbore may be separated via distillation into a variety of liquid and gaseous products, such as gasoline, kerosene, propane, natural gas, and asphalt, and chemical intermediates used in the manufacture of consumer products, such as plastics and pharmaceuticals. Unfortunately, global petroleum reserves have been declining as worldwide consumption of petroleum products continues to increase. In addition, the costs associated with petroleum recovery have increased as more secondary and tertiary methods are used to recover the dwindling supplies of petroleum. These rising costs are reflected in the increased cost of fuels and other consumer products.
In light of its limited future, producers have sought out alternatives to petroleum. One such alternative is oil shale, which is an organic-rich rock found in certain subsurface formations. Oil shale may have been formed from ancient organic deposits that were not exposed to enough heat and/or pressure to be transformed into petroleum. Thus, the hydrocarbon content of oil shale may be different from that of petroleum. However, oil shale may be recovered using methods similar to those used for petroleum recovery. For example, wells may be drilled into oil shale deposits and various techniques, such as hydraulic fracturing or other stimulation, may be used to recover the oil shale. In addition, shale gas, which is similar to natural gas, may be recovered from oil shale deposits. Oil shale and shale gas may be used successfully as fuels or chemical intermediates. Thus, the development of oil shale deposits may be expected to increase as worldwide supplies of petroleum and other hydrocarbons decrease, and current estimates of global oil shale deposits exceed those of petroleum.
Although hydrocarbon deposits may be found in many parts of the world, these deposits vary widely in their organic compound content and other characteristics. Thus, for commercial and economic reasons, producers may prefer to develop hydrocarbon deposits with relatively higher amounts of hydrocarbons. Surface-based methods, such as seismic studies that involve sending sound waves into the ground and analyzing their reflections, may be used to identify potential hydrocarbon deposits. Subsequently, drilling may be used to physically obtain samples from the subsurface formations. These samples, referred to as core samples or simply cores, may be sent to laboratories or other facilities located away from the wellsite for analysis. Various tests of the core samples may be conducted to estimate the content of organic material in the hydrocarbon deposit. For example, the hydrocarbons may be present in pore spaces of the subsurface formation. If present, the quantity or degree of hydrocarbon saturation is identified to help determine the commerciality of hydrocarbon production of the subsurface formation. Several methods for determining the hydrocarbon quantity exist. For example, the gas saturation Sg or the oil saturation So (expressed as percent of pore space) may be calculated using the following equation:Sg(or So)=100−Sw  (EQUATION 1)where Sw is the water saturation (expressed as percent of pore space). Accordingly, the water saturation Sw may be calculated using the following equation:Sw=(F*Rw/Rt)1/n  (EQUATION 2)where F is a formation resistivity factor, Rw is a formation water resistivity, Rt is a true formation resistivity, and n is a water saturation exponent. Thus, values for all the variables in these equations are needed to solve for the gas saturation Sg or the oil saturation So in the pore space.
Water, which is referred to as formation water, is generally present within the pore spaces of subsurface formations, such as hydrocarbon deposits. The formation water resistivity Rw is dependent on the ionic composition of the water solution. The formation water resistivity Rw is further dependent on temperature, although a well-based transform may be used to enable translation from one temperature to another. As indicated by Equation 2 above, the formation water resistivity Rw is one of several variables needed to solve for the water saturation Sw. Rw may be determined by:                1. Calculation using resistivity and porosity logs.        2. Measurement of resistivity or salinity of water produced at the surface from subsurface formations.        3. Measurement of resistivity or salinity of water contained in cores of subsurface formations.For example, in the second method above, formation water is collected and brought to the surface for analysis. This collected water is referred to as produced water. By using the produced water method, the formation water resistivity Rw may be directly identified. However, sample variability and availability may hinder this method. For example, sources of water other than the formation water contained in the pore spaces may contaminate the produced water, thereby altering the measured formation water resistivity Rw. Examples of other sources of water include water introduced during drilling, water migrating through fracture conduits within the earth, and water of condensation. In addition, many formations do not produce any water. Thus, other approaches may be used to determine the formation water resistivity Rw because of the uncertainty and possible unavailability inherent in produced water analysis.        
The measurement of the resistivity of water contained in cores of subsurface formations may overcome some of the limitations of produced water analysis. For example, the cores may analyzed using direct displacement or distillation/leach techniques. In direct displacement, force is used to expel the pore water from the subsurface sample. For example, displacement may be achieved via high-speed centrifugation or by a high-pressure oil drive. Further, depending on the characteristics of the core, it may be crushed or ground into a powder to increase the amount of water expelled. The displaced water may then be directly measured for formation water resistivity Rw. Such displacement techniques may be influenced by the ability of the formation water to move through the subsurface sample, referred to as permeability, and the volume of formation water present in the sample. In addition, direct displacement techniques may take days to complete and are limited in their ability to expel formation water from the core.
Distillation/leach is an indirect technique to identify the formation water resistivity Rw of subsurface samples. In this technique, the formation water present in the sample is distilled, captured, and quantified, leaving behind precipitated salts in the dried core sample. The core sample is then contacted with a known distilled water volume and leached to extract the salts remaining in the dried pore spaces. Following leaching, the leach water is analyzed for ion content. The ion analysis and the volume of water distilled from the core sample are combined to determine the ion content (salinity) present in the pore spaces. The formation water resistivity Rw may then be calculated from the salinity of the pore water using established techniques. Unfortunately, distillation/leach tests may take days to complete and may be influenced by geochemical reactions that occur during the hydrolysis of minerals in the core sample. Additionally, cation exchange between the ions present in the leach water and any clays present in the core sample will influence the analyzed ion content. Thus, accurate results may require a geochemical model to help identify the salinity that was originally present in the pores of the core sample.
Thus, current techniques for determining formation water resistivity Rw possess several shortcomings. For example, certain tests may be destructive, involving crushing and/or grinding of the subsurface sample into smaller particles. Other tests may involve heating, applying liquids, or other preparatory steps. Thus, current tests may be costly, complicated, and/or time-consuming because of the preparation and steps associated with such testing and the need to ship the subsurface sample to facilities remote from the wellsite.